Hydraulic Fracturing with Strong, Lightweight, Low Profile Diverters

ABSTRACT

Low profile diverters for, and the use of such diverters in, fracing operations to stimulate production of oil and gas are capable of seating against and temporarily sealing perforations, even when frac fluid is being pumped at high rates and pressures, or in horizontal or highly deviated well bores, where conventional ball sealers cannot be reliably used because of high flow rates and pressures.

The invention claims benefit of provisional application no. 62/259,681,filed Nov. 25, 2015, the entire contents of which is incorporated hereinby reference for all purposes.

FIELD OF INVENTION

The invention pertains to hydraulic fracturing of subterraneangeological formations to stimulate production of oil or natural gas fromthe formations.

BACKGROUND

Generally, more porous rock has more space for holding oil and gas.However sometimes relatively porous rock has low permeability.Permeability is a measure of the ease with which fluids will flowthrough rock. Shale is an example of rock with relatively high porositybut very low permeability due to the small grain size, which reduces thepaths through which hydrocarbons can flow. Porosity of a rock is ameasure of its capacity to contain or store fluids and can be calculatedas the pore volume of the rock divided by its bulk volume. Rock'sprimary porosity is determined at the time of its deposition, butsecondary porosity develops after deposition of the rock and includesspaces created by leaching or natural fracturing.

One way to stimulate or improve production from low permeability rockformations containing oil or gas is to create or enlarge fractureswithin the formations by a process called hydraulic fracturing(“fracing”). Fracing involves pumping hydraulic fluid (“frac fluid”) athigh pressures and rates into a well bore, and then into the formationthrough perforations formed in the well casing. Perforating a wellcasing to create openings through which hydrocarbons can flow into thewell may induce some fracturing within in the formation immediatelyadjacent the perforation. Fracing extends fractures already present inthe formation, and causes new fractures, resulting in a network offractures that substantially increases the permeability of the formationnear the well bore.

In a “sand” frac a propping agent mixed with and carried by the fracfluid into fractures created and/or enlarged in the formation by thehigh pressure frac fluid. The sand fills the fractures and holds therock formation faces apart after pumping of the frac fluid finishes,thereby propping open the fractures through which oil and gas flow morefreely into the well bore. An “acid” frac typically does not require useof a propping agent, as the acid creates the fractures in the formationand etches or dissolves the fracture faces unevenly, thereby formingdissimilar fracture faces that can only partially close leavingfractures through which oil or gas can flow more freely.

Common examples of proppants include silica sand, resin-coated sand, andceramic beads (and possibly mixtures of them.) Because silica sand isthe predominant proppant used for fracing, “sand” has become petroleumindustry jargon for any type of proppant or combination of proppantsused in fracing. Therefore, the term “sand” in the specification andclaims refers to any type of propping agent, or combinations of them,suitable for holding open fractures formed within a formation by afracing operation unless otherwise plainly stated. The term “frac fluid”will be used to refer to any type of hydraulic fluid used for fracingthat may be used to form fractures and/or enlarge natural fractures inthe formation. Frac fluids may be water-based, oil-based, acid oracid-based, and or foam fluids. Additives can be used to control desiredcharacteristics, such as viscosity. Furthermore, references to “fracfluid and sand” in the context of fracing are intended to also includefrac fluid and acid unless the context states or plainly indicatesotherwise.

Because of differences in permeability of the rock at each of theperforations due to different porosities or existing fractures (bothnaturally occurring and caused by perforating the casing), the rate atwhich frac fluid flows through perforations distributed a long a wellbore may, and almost always does, vary along the length of the wellbore. When stimulating vertical wellbores over 60 years ago thepetroleum industry frequently used a high number of perforations (up to4 perforations per foot of casing) throughout most of the oil and gaspay zones of a well bore. Such a large number of perforations resultedin the frac fluid and sand flowing first into more permeable rock. Thisresulted in fractures in the more permeable rock formations being packedwith too much of the sand (or acid), which was intended to bedistributed reasonably equal through the perforations. The lesspermeable formations were, consequently, not being sufficientlyfractured. Solid, hard rubber balls, referred to as “ball sealers,” wereused to stimulate selectively the formation in vertical wellbores withan excessive number of perforations. After pumping a portion of the fracfluid with sand or acid, multiple ball sealers were pumped into the welland carried by the frac fluid to the perforation being stimulated. Theballs temporarily sealed some of the perforations—those adjacent tofractures formed in the more permeable rock—and diverted the frac fluid,with the sand or acid, away from the stimulated perforations to otherperforations in the next most permeable zone of rock that had not yetbeen stimulated. After pumping of frac fluid ceases, the ball sealers,no longer being held against the perforations by the differentialpressure between the frac fluid within the well bore and the formation,fall off of the perforations to allow hydrocarbons from the fracturedformation to flow into the well. However, the need for the relativelylarge and heavy ball sealers in vertical wellbores was minimized whenindustry began to selectively perforate only the better permeable zones(commonly referred to as “limited entry”).

For horizontal or highly deviated directional oil and gas wells, theconventional petroleum industry practice today is to frac lateral wellbores in stages. The length of a lateral portion of a well may be 4,000feet to 7,500 feet, or substantially more, with cement typically sealingthe void space between the casing and the hole. As with vertical wells,perforations in the well casing are formed to inject the frac fluid andsand or acid into the formation to cause it to fracture. Often 15 to 30,and sometimes more, stages are employed to frac a lateral well boreextending 4,000 to 7,500 feet or more. Each frac stage may have 4 to 8clusters of perforations, with each cluster typically having 6perforations.

The purpose of fracing in multiple stages is to distribute a generallyequal amount of frac fluid and sand to all perforations in a manner thatachieves optimal stimulation of each perforation along the entire lengthof the lateral portion of the well bore, thereby creating extensivecracking/fracturing of the rock formation surrounding the casing alongits entire length. Each frac stage is isolated from the other stages andperforated and fraced separately. The petroleum industry experience offracing a huge number of horizontal wells drilled to date appears toindicate that a large number of stages are required to ensure that areasonably equal and sufficient volume of frac fluid and sand are pumpedinto each perforation. In the past few years, developments in hydraulicfracture technology indicate that superior stimulation results areachieved by using larger volumes of frac fluid and sand (15 milliongallons and 15 million pounds of sand and more) pumped at extremely highrates (80 to 100 barrels per minute) and pressures (8,000-9,000 psi andmore). The velocity of the frac fluid through the wellbore may reach orexceed 90 feet per second. Therefore, the industry continues to use thehigh-cost, multiple frac stages in an effort to distribute generallyequal amounts of frac fluid and sand to all perforations in the lateralcasing.

The commercial value of drilling horizontal wells with longer lateralsand multiple stages fraced with larger volumes of frac fluid and sandpumped at high velocity and pressure has been established by achievingrobust wells that have higher oil and gas producing rates and estimatedultimate recoveries of oil and gas. Effective frac stimulation of mostor perhaps all of the perforations in a horizontal casing creates anextensive fracture system that opens and connects more reservoir rock tothe wellbore. However, such frac jobs with a large number of stages aretime consuming and expensive due to the repetitive plug, perforate andfrac operation required to isolate and frac each individual stage.Completion costs typically represent about one-half of the totaldrilling and completion costs of a horizontal well. Although it istempting to reduce costs by reducing the number of frac stages andincreasing the number of perforations to be stimulated per stage, fewerstages with more perforations per stage risks partial or unequalstimulation of the perforations within the stages. Wells withineffective stimulation have lower initial production rates and lowerultimate recovery of oil and gas.

SUMMARY

Fracing with low profile diverters, such as those described below, toselectively seal perforations temporarily during fracing to help todistribute frac fluid and sand uniformly in horizontal, deviated, orvertical wells reduces the need for a large number of frac stages. Suchlow profile diverters are capable of seating on and temporarily sealingperforations, even when frac fluid is being pumped at high rates andpressures. The diverters are large enough in two dimensions to cover andtemporarily seal perforations in well casing, but relative thin in athird dimension orthogonal to the first two, and thus present a lowprofile, to reduce drag when seated on a perforation. The diverters areconstructed to withstand the pressure of frac fluid pumped at highpressures against the diverter while it continues to temporarily seal aperforation. In comparison, conventional ball sealers are relativelylarger and heavier, and have a large cross-sectional area. At high flowrates and pressures, frac fluid and sand may be flowing through aperforated liner at more than 90 feet per second, making it less likelythat ball sealers will seat and remain seated to seal a perforation.

A process of fracing of a relatively long—4,000 to 7,500 feet, ormore—wellbore using such diverters can be accomplished with asubstantially reduced number of frac stages, and, in some cases, nostages.

In one embodiment of such a method, a predetermined amount of a fracfluid is pumped with sand or acid into a wellbore to cause fracturing ofsubterranean rock formation adjacent to a plurality of perforationsformed in the casing of the wellbore. Prior to finishing pumping thepredetermined amount of frac fluid with sand or acid into the well bore,diverters are introduced into the frac fluid entering the wellbore. Thenumber is sufficient to seat against a portion, but not all, of theplurality of perforations to obstruct and temporarily seal them, therebycausing frac fluid to flow toward the remaining ones of the plurality ofperforations not being obstructed while the frac fluid continues to bepumped under pressure into the well bore. Each of the diverters has,when seated on one of the plurality of perforations, a first surfacefacing the perforation opening and a second surface facing generally inthe direction of a center line of the well bore, the area of the firstsurface being greater than the area of the perforation opening. Each ofthe diverters, when seated, presents a cross-sectional area to the flowof frac fluid through the well bore during pumping that is substantiallysmaller than the first and the second surface areas. Using this method,diverters are carried by the frac fluid to the stimulated perforationsat which point they will temporarily seal off the stimulatedperforations forcing the frac fluid and sand to enter the non-stimulatedperforations in the next most permeable zone.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a simplified, schematic illustration of a well site with awell bore within a formation undergoing hydraulic fracturing.

FIG. 2A is representation of a prior art ball sealer.

FIG. 2B is a representation of a first embodiment of a low profilediverter in cross-section.

FIG. 2C is a representation of a second embodiment of a low profilediverter in cross-section.

FIG. 2D is a representation of a third embodiment of a low profilediverter in cross-section.

FIG. 2E is a representation of a fourth embodiment of a low profilediverter in cross-section.

FIG. 2F is a representation of a fifth embodiment of a low profilediverter in cross-section.

FIG. 3 represents a short section of a representative non-perforatedcased horizontal wellbore upstream of the perforated representativewellbore shown in FIG. 4.

FIG. 4 illustrates the small section of a representative wellboredownstream of the representative wellbore shown in FIG. 3, withperforations formed therein and frac fluid flowing through the wellboreand perforations into the adjacent formation to cause fracturing.

FIG. 5 illustrates the small section of a representative wellbore ofFIG. 4, with the introduction of low profile diverters into the flow offrac fluid within the wellbore, before they seal perforationstemporarily.

FIG. 6 illustrates the small section of a representative wellbore ofFIG. 5, with the diverters previously introduced into the flow of fracfluid sealing perforations adjacent to stimulated formations.

DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS

The following description, in conjunction with the appended drawingsdescribe one or more representative examples of embodiments in which theinvention claimed below may be put into practice. Unless otherwiseindicated, they are intended to be non-limiting examples forillustrating the principles and concepts of subject matter that isclaimed. Like numbers refer to like elements in the drawings and thedescription.

FIG. 1 is a schematic illustration of a representative example of awellbore undergoing fracing. It is not to scale. In this implementationthe well site 100 has a well head 102 disposed at a top of a wellbore.The well head 102 is be coupled to a source of frac fluid 104. Thesource may be comprised of one or more tanks, reservoirs, or otherstorage structures for fluid and sand or acid. The well head 102 mayinclude, or have coupled with it, various equipment and sensors, such asa surface pressure sensor 103. The surface pressure sensor 103 may bearranged to measure fluid pressure in the wellbore at the wellhead 102.Frac fluid stored in the fracing fluid storage 104 may be mixed with asand or acid. Alternatively, sand or acid is introduced to the fluid ator upstream of the wellhead 102. In some implementations, for examplewhen the target subterranean formation is a carbonate formation, thefrac fluid may contain acid, in which case proppants may be unnecessaryas the acid eats away the formation so that it cannot close. The wellhead 102 controls the injection of frac fluid into a wellbore 106. Thewellbore may be horizontal, deviated, or vertical. In the example ofFIG. 1, wellbore 106 extends horizontally into a target subterraneanformation 110. The wellbore 106 is cased using a steel pipe 108 that iscemented in place. However, in some applications, the casing may not becemented. Also, a casing liner may be used for the lateral section ofthe wellbore. The invention is not limited to any particular casingmethod.

Perforations 112 are formed through the well casing 108 to expose thesurrounding subterranean formation 110 to the interior of wellbore 106,thereby allowing pressurized frac fluid with sand or acid to be injectedthrough the perforations into the subterranean formation. The wellcasing may be perforated using any known method that producesperforations of a relatively consistent and predictable size. Forexample, perforations 112 may be formed by lowering shaped blastingcharges into the well to a known depth, thereby creating clusters ofperforations at desired points along the wellbore 106. In a typicalapplication, perforations will, for example, be 0.4 to 0.5 inches indiameter, but in other applications they may have smaller or largerdiameters.

During fracing operations, frac fluid will be pumped through the wellhead 102 and into the wellbore 106. The fluid will flow toward theperforations 112, as indicated by flow lines 114, and then out of theperforations 112 and into formation 110 to create new or enlargedfractures 116 within the formation. In this demonstrative, schematicillustration of FIG. 1, fractures 116 of the formation is indicated nextto only some of the perforations, but not all. The fractures in thisexample are occurring in a portion or area of the formation into whichmore frac fluid is flowing due to, for example, higher permeability thanthe formation adjacent to the remaining perforations, which areindicated in the figure as having no new or enlarged fracturing, thoughin practice, new fractures or enlargement of existing fractures may infact be taking place to a smaller degree.

In some implementations, a downhole pressure sensor (or pressure sensorarray) 120 may be placed lowered into the horizontal portion of wellbore106 near the perforations 112 to measure the pressure of the frac fluidclose to perforations 112.

Although, in this example, the wellbore is not divided into multiplefrac stages, the wellbore within the formation to be fraced can bedivided into frac stages, with each stage separately isolated andfraced. The diverters and fracing method described below can be usedwith multiple stage fracing. However, the diverters allow for areduction in the number of stages that is otherwise required to achievesimilar results. They can also be used to frac without stages the entirewellbore within the zones of the formation expected to produce oil orgas.

FIG. 2A illustrates, for purposes of comparison, a conventional, solidball sealer 200 of the type found in the prior art. It has uniformdiameter. Its width “W” is equal to its height “T,” which is equal toits diameter. The diverters 202, 204, 206, 208 and 210 of FIGS. 2B-2Fillustrate different cross-sectional shapes of a new type of diverterthat is relatively thin and lightweight (as compared to ball sealers)and strong. The low profile diverters are sized to extend over andtemporarily seal stimulated perforations, thereby diverting the flow ofthe fracing fluids and proppants to non-stimulated perforations. Eachsuch low profile diverter has, in a preferred embodiment, an impermeablebody with dimensions measured along each of two axes (the x and z axesin the coordinate frame illustrated in the figures) large enough tocover and temporarily seal a perforation in a well casing of a size thatis typically made or that might be made for the particular application.In these examples each has the same width W, which is the diameter ofball sealer 200 (FIG. 2A). But, unlike a ball sealer, each has adimension along an axis orthogonal to the other two axes (the y-axis)that is a substantially smaller than dimensions of the diverter alongthe first two axes, resulting in a relatively thin cross-section (orprofile) that reduces drag caused by fluid flowing past the diverterwhile it seals a perforation. Due to the reduced drag such a diverter ismore capable of seating onto perforations and sealing them off withoutbeing unseated by continued fluid flow over or past the diverters. Theshape of the outer circumference of diverters in a plan view, whichwould be along the y-axis, or the cross-sectional shape of the diverterswhen sectioned normal to the y-axis, is circular in the examples given.However, other shapes could be used as long as the shortest dimension ofthe diverter in the x and z dimensions is large enough to cover andtemporarily seal the expected perforations. Non-limiting examples ofsuch shapes are oval, squarer, and polygonal shapes. Other shapes arepossible.

When introduced into a flow of frac fluid into a wellbore duringfracing, each diverter 202 to 210 is intended to temporarily seal oneperforation after it has been stimulated with frac fluid and sand oracid. Though the specific cross-sectional areas for these diverters willvary based on different design and manufacturing considerations, theillustrated cross-sections of diverters 202 to 210 have much lowercross-sectional areas—preferably, 75 to 95 percent less than the ballsealer 200 (or a comparable ball sealer capable of sealing similarlysized perforations.) They are, therefore, subject to substantially lessdrag force exerted by fast moving frac fluid than a traditional ballsealer. This large reduction in drag force allows the diverters to seaton and form a temporary seal of the stimulated perforations more easilyand reliably. The relatively small cross-sectional area of suchdiverters thus minimizes the risk that the high velocity frac fluidflowing through the perforated liner could cause (1) failure of somediverters to seat on and seal stimulated perforations, or (2) divertersto be unseated from the stimulated perforations before completion of thefrac job. The temporary seal is broken, and the diverters unseat, whenthe frac fluid pressure drops and the pressure differential across thediverter drops to the point that there is insufficient pressure to holdthem against the perforations, thus allowing hydrocarbons to flow intothe well from the formation.

Turning now to the specific examples of low profile diverters shown inFIGS. 2B-2F, the diverters are positioned to show their minimumcross-sectional width W along the x axis of the coordinate frameadjacent to each of the figures. As previously mentioned, each is shownwith the same width as ball sealer 200 for purposes of comparison.Diverter 202 of FIG. 2B is shaped generally as a discus having anoverall or greatest thickness T (measured along the y axis). Thegreatest thickness of the diverter 202 is in the center, and thethickness tapers towards side edges of the diverter. In comparison tothe ball sealer 200, the discus shaped diverter 202 has the same minimumwidth W, but a considerably smaller thickness T₁. The cross-sectionalarea of diverter 202 is much less than the cross-sectional area of theball sealer 200, and has a resistance to the flow of frac fluidestimated to be 25% of the resistance of the ball sealer 200.Accordingly, the discus shaped diverter 202 is capable of sealing aperforation, while having a much smaller cross-sectional area, andtherefore a greatly decreased resistance to flowing frac fluid.

Diverter 204 of FIG. 2C is shaped as an erythrocyte, which has itsgreatest thickness T₂ along its outer perimeter or edge, but has centerregion with having a smaller thickness T₃. The resistance to frac fluidflow of the erythrocyte-shaped diverter 204 is estimated to be about 20%of the resistance of the ball sealer 200.

Diverter 206 of FIG. 2D is shaped like a saucer, having a convex bottomsurface 214 with a first radius and a concave top surface 212 with asecond radius different than the first radius. In this embodiment, theradius of the concave top surface 212 is greater than the radius of theconvex side 214 so that the sides converge and intersect at outer edge216 of the diverter. The diverter 206 has an overall thickness T₄measured vertically from a lowest point of the convex bottom surface 214to edge 216. Depending on the thickness Ts (the actual thickness ofwhich may depend on the materials and expected pressures), is estimatedto have approximately 10% of the resistance of fluid as that of the ballsealer 200.

Diverter 208 of FIG. 2E is shaped as a disk, with a generally consistentthickness T₆ across its width W. In example shown, its resistance to theflow of frac fluid is estimated to be about 8% of that of the ballsealer 200. If the thickness is decreased to T₇, as shown by the examplediverter 210 in FIG. 2F, it's estimated resistance to the flow of fracfluid drops to about 5% of that of the ball sealer 200.

The actual cross-sectional area of these diverters 202, 204, 206, 208,and 210 may vary from each other, even if intended to seal the samesized perforations. The exemplary diverters of FIG. 2B-2F have flat tocurved surfaces to facilitate forming a temporary seal of theperforations. Furthermore, a diverter is constructed to be strong enoughto seal the perforation without failing under the differential pressureacross the diverter (the pressure acting against the surface of thediverter facing the inside of the casing less the pressure actingagainst the surface of the diverter facing the perforation) to which itis expected to be subject when seated on a perforation. The differentialpressure will be the difference between the pressure of the frac fluidon the diverter inside the casing, acting against the diverter whensealing a perforation, which is a function of the pumping pressure onthe frac fluid and the hydrostatic pressure of the frac fluid within thecasing, and any fluid pressure outside the casing. In one embodiment,each of the diverters 202 to 210 is capable of withstanding at least5000 psi of differential pressure without failing. In anotherembodiment, each diverter can withstand a differential pressure of atleast 7500 psi without failing. In yet another embodiment, each divertercan withstand a differential pressure of at least 10,000 psi withoutfailing. Furthermore, a diverter may, optionally, have a flexible anddurable surface or coating to enhance sealing of the perforations. Thediverters 202 to 210 may be partly or entirely constructed out ofmaterial or materials that allows them to be flexible, further enhancingtheir ability to form a seal over perforations 112. In some embodiments,diverters 202 to 210 may be constructed out of a composite material,which can be stronger and lighter than steel.

The shapes of diverters 202 to 210, particularly diverters 202, 204 and206, allow them to be hollow to increase their displacement withoutincreasing their weight. Therefore, the diverters may have a weight thatis heavier, lighter or equal to the weight of its displacement of fracfluid. The embodiments of diverters 202, 204 and 206 are shown infigures as being hollow. However, in alternative embodiments, thesediverters could be made solid. The disk and wafer shaped diverters willbe strong and lightweight without necessarily being hollow.

Referring briefly back to FIG. 1, frac fluid is shown being pumpeddownhole from the well head 102 and into the wellbore 106, as indicatedby the arrows with the wellbore. At this point, pumping has continuedlong enough to begin to fracture parts of the formation 110. The fracfluid is shown flowing into perforations 112 associated with relativelylarger fractures 116, indicating that those parts of the formation havebeen stimulated. The large fractures are in zones or areas of theformation with relatively high permeability. The less developed fracture118 is intended to illustrate an area of less permeability that has notyet completed fracturing. The other perforations have little to nofracturing of the formation next to them. Those areas of the formationhave lower permeability and are not receiving enough frac fluid to startto fracture because it is flowing mostly into the parts of the formationwith higher permeability.

Once some of the most permeable areas of the formation are approachingfull stimulation, a predetermined number of thin or low profilediverters such as of FIGS. 2B-2F, are introduced at or near the wellhead into the flow of frac fluid entering the well bore, withoutstopping pumping of frac fluid and sand. These diverters are intended totemporarily seal only those perforations next to areas within theformation that have been fully stimulated—those, for example, next tofractures 116—and thus divert frac fluid and sand to less fractured oryet-to-be fractured areas of the formation.

Referring now to FIGS. 3 to 6, FIG. 3 illustrates a small section 300 ofa horizontal wellbore casing upstream of the section 300 of casing withperforations (see FIG. 4), with flow arrows 302 indicating the directionof fluid flow downhole. The flow arrows 302 indicate how fluid flows inunperforated casing before reaching the perforated casing 300 shown inFIG. 4. FIG. 4 shows multiple perforations 402, after frac fluid hasbegun to be pumped under high pressures and at high flow rates downholeand through the wellbore. The flow of frac fluid is indicated by flowlines 404. All of the perforations are not sealed and therefore open.The pressurized frac fluid flows into the perforations adjacent to theareas or zones of the subterranean formation 406 where it is mostpermeable, as shown by directional lines 404. In the figure theperforations are adjacent to rock having, essentially, the same amountof permeability. Thus, in this example, it is shown flowing into all ofthe perforations. Although not shown, frac fluid, and thus also sand oracid, is not flowing, or flowing at lower rates, into perforationselsewhere within the segment of the wellbore that is being fraced (asegment corresponds to one frac stage or length of well bore undergoinga fracing operation) that are adjacent to less permeable parts of theformation. Thus, fractures 406 are being fractured first. Once theformation adjacent to perforations 402 are fully stimulated, meaning thefrac fluid has fractured the subterranean formation 406 and thefractures 408 are packed with sand to hold them open, a predeterminednumber of low profile diverters, such as those shown in FIGS. 2B-2F, arepumped into the flowing frac fluid stream to seat and temporarily sealperforations 402 and thereby the frac fluid is redirected or diverted tothe perforations within the wellbore adjacent to less permeable areas offormation to create fractures 118.

In FIG. 5 the low profile diverters 500, which in this example aresaucer shaped but can be any of any low profile shape capable of sealingagainst the perforations, are shown entrained in the flow of frac fluidand being moved toward perforations 402 by the flow of the frac fluidand sand into the perforations. In FIG. 6, the low profile diverters areshown seated on the openings of the perforations, engaging the edges ofthe perforations and thus temporarily sealing the perforations againstsubstantial frac fluid flow. (A small amount of leakage may occur evenwhen sealed.) The high pressure of the frac fluid within the well borepushes against the seated diverters with sufficient force to keep themin place while the frac fluid flows past them, as indicated by the fracfluid flow lines 404 in the figure. Because of the low profile of thediverters, the frac fluid moving at a high rate within the wellbore isless likely to dislodge the low profile diverters as compared toconventional ball sealers.

Each diverter should temporarily seal one perforation, and only aperforation that has likely been stimulated with frac fluid and sand oracid, assuming that the diverter is introduced into the frac fluid flowat the right time. The number of diverters that are introduced into theflow of frac fluid is less than the number of perforations beingstimulated. The pumping of the frac fluid continues and, after a periodof time, an additional selected number of additional diverters can beintroduced into the flowing frac fluid stream to temporarily seal some,but not all, of the remaining perforations. This process of continuingto pump frac fluid for some period of time before introducing a selectednumber of additional diverters is repeated as many times as necessary toselectively frac progressively less permeable parts of the formationuntil all of the volume of frac fluid with sand and the number ofdiverters designed and purchased for the job have been essentiallydepleted by pumping indicating that the stimulation of all perforationshave been reasonably completely.

Use of low profile diverters as described above allows for the number offrac stages to be reduced, and possibly eliminate of the need for fracstages, even for wells with relatively long wellbores, even for longlaterals that require fracturing at very high rates and pressures, ascompared to current methods that do not make use of low profilediverters.

The following is an example. In this example, a 7,500 foot horizontallateral well may have 30 stages of fracture stimulation with each stagebeing individually perforated with 36 perforations (total of 1,080perforations for 30 stages), and then fraced with a “batch” of fracfluid and sand to stimulate the 36 perforations. Continuing with thisexample, rather than individually perforating and fracing each of the 30stages, the method described herein could achieve relatively evendistribution of frac fluid and sand along the later well using, in thisexample, 4 stages of frac stimulation, with 270 perforations per stage.(perforating approximately 1/4 of the lateral casing length beginning ator near the end of the casing). Therefore, continuing with this example,the number of frac stages required would be reduced from 30 to 4 stages.Stage 1 begins with perforating the lateral casing with 270 perforationsfollowed by continual pumping of frac fluid and sand for the duration ofStage 1. After pumping the predetermined volume of frac fluid and sand,10 to 20 (or more or fewer) diverters are injected into the flow of fracfluid and sand to be carried in the fluid stream to seat and temporarilyseal those perforations in the most permeable zones in the formation 110that have been stimulated with frac fluid and sand. Once the divertersseat on and temporarily seal the stimulated perforations, the flowingfrac fluid with sand is redirected or diverted to non-stimulatedperforations in the wellbore adjacent to the next most permeable zonesin the formation to create new fractures and expand natural fractures inthe rock which are packed with sand to prevent closure of the fractures.Such Stage 1 procedure is repeated with the selective stimulation ofperforations in the progressively next most permeable zones and seatingon and temporarily sealing these perforations with diverters until all270 Stage 1 perforations have been fully stimulated. At this time, adrillable ball or plug is pumped into the frac fluid stream to terminatethe Stage 1 frac job. The first stage is thereby sealed it off from thesubsequent Stage 2 frac job. Such balls are commonly used in multistagefrac jobs for horizontal wells with long laterals. The first ball pumpedat the end of Stage 1 has the smallest outside diameter with subsequentballs to end frac Stages 2 and 3 (no ball is needed to end frac Stage 4)having progressively larger outside diameters. The balls are sized toseat and seal in the receptacle in a special collar located in thecasing immediately upstream of the Stage 1 perforations. Note that theuse of ball drops to isolate a stage that has been fracked in thismanner is just one example of a method for isolating stages. Othermethods to isolate a stage could be used. The method is not limited toany particular method. The final pumping of the Stage 1 frac jobcontinues until the first ball seats and seals off the Stage 1perforations. The low profile diverters and method of using them shouldprovide a more effective and efficient method to achieve reasonablyequal distribution of sand in all perforations and, thereby,substantially reduce the cost to complete a well, particularlyhorizontal and highly deviated wells.

In the event two or more stages are required to achieve effectivestimulation with reasonably equal distribution of frac fluid and sandthroughout the entire lateral length of the casing, each subsequentstage would be separated from the stimulated stages. One example of howthis is currently done is with a conventional drillable ball or plug(known as the “plug and perforate” process). However, the processesdescribed herein are not limited by the method use for separating orisolating stages. Such use of the diverters should enable severalbatches of frac fluid and sand to stimulate many more perforations perfrac stage. Substantially reducing and possibly eliminating the multiplefrac stages currently required to stimulate a horizontal well willresult in major reduction in the direct cost of a horizontal well.

The foregoing description is of exemplary and preferred embodiments. Theinvention, as defined by the appended claims, is not limited to thedescribed embodiments. Alterations and modifications to the disclosedembodiments may be made without departing from the invention. Themeaning of the terms used in this specification are, unless expresslystated otherwise, intended to have ordinary and customary meaning andare not intended to be limited to the details of the illustrated ordescribed structures or embodiments.

What is claimed is:
 1. A method of stimulating production ofhydrocarbons from a well having a casing through which has been formed aplurality of perforations, the method comprising: pumping into thewellbore under pressure a hydraulic fracture fluid containing proppantor an acid; after pumping a predetermined amount of the hydraulicfracture fluid containing proppant or acid into the well bore,introducing into the flow of hydraulic fracture fluid entering the wellbore, without stopping pumping, a predetermined number of diverters forseating against a portion, but not all, of the plurality of perforationsto obstruct and temporarily seal them, thereby diverting the hydraulicfracture fluid containing proppant or acid toward the remaining ones ofthe plurality of perforations not being obstructed; and continuing topump the hydraulic fracture fluid containing proppant or acid underpressure into the well bore; wherein each of the diverters has, whenseated on one of the plurality of perforations, a first surface facingthe perforation opening and a second surface facing generally in thedirection of a center line of the well bore, the area of the firstsurface being greater than the area of the perforation opening, andwherein each of the diverters, when seated, presents a cross-sectionalarea to the flow of hydraulic fracture fluid containing proppant or acidthrough the well bore during pumping that is substantially smaller thanthe first and the second surface areas.
 2. The method of claim 1, thepumping of hydraulic fracture fluid containing proppant or acidcontinues without interruption when introducing the diverters into theflow of hydraulic fracture fluid.
 3. The method of claim 1, wherein,when one of the plurality of diverters is seated on one of the pluralityof perforations, it is held in place by pressure of the hydraulicfracture fluid within the well bore acting against the second surface ofthe diverter.
 4. The method of claim 1, wherein the permeability of thesubterranean formation adjacent to each of the plurality of stimulatedperforations that are being at least partially obstructed andtemporarily sealed by the predetermined number of diverters is greaterthan the permeability of the subterranean formation adjacent to each ofthe remaining ones of the plurality of perforations that are not beingobstructed by a diverter.
 5. The method of claim 1, wherein each of theplurality of diverters has a shape substantially similar to the shape ofan object chosen from a group consisting essentially of a discus,erythrocyte, saucer, disk, and wafer.
 6. The method of claim 1, whereineach of the plurality of diverters is hollow.
 7. The method of claim 1,wherein each of the plurality of diverters is capable of withstanding adifferential pressure of at least 5,000 pounds per square inch withoutfailing.
 8. The method of claim 1, wherein each of the plurality ofdiverters is capable of withstanding a differential pressure of at least7500 pounds per square inch without failing.
 9. The method of claim 1,wherein each of the plurality of diverters is capable of withstanding adifferential pressure of at least 10,000 pounds per square inch.
 10. Themethod of claim 1, wherein each of the plurality of diverters, whenseated on one of the plurality of perforations, presents across-sectional area to the flow of hydraulic fracture fluid through thewell bore during pumping that is 25% or less than the cross-sectionalarea presented by a ball-shaped diverter seated on the one of theplurality of perforations.
 11. The method of claim 1 wherein thepermeability of the subterranean formation adjacent to those of theplurality of perforations being obstructed and temporarily sealed by thediverters is greater than the permeability of the remaining ones of theplurality of perforations not being obstructed and temporarily sealed bythe diverters.
 12. A method of stimulating production of hydrocarbonsfrom a well bore having a casing, the method comprising: establishingwithin the well bore a plurality of frac stages isolatable from eachother; and for each of the plurality of frac stages, forming a pluralityof perforations in the casing along a first section of the well bore;pumping into the wellbore under pressure the predetermined amount of ahydraulic fracture fluid containing proppant or acid; and after apredetermined amount of hydraulic fracture fluid containing proppant oracid has been pumped into the well bore, introducing into the flow ofhydraulic fracture fluid containing proppant or acid entering the wellbore, without stopping pumping, a batch of diverters, the batch ofdiverters containing fewer diverters than the number of perforations inthe plurality of perforations for seating against a portion, but notall, of the plurality of perforations to temporarily obstruct and sealthem at least partially, thereby diverting the hydraulic fracture fluidcontaining proppant or acid toward the remaining ones of the pluralityof perforations not being obstructed for fracturing the subterraneanformation adjacent to them; and continuing to pump the hydraulicfracture fluid containing proppant or acid under pressure into the wellbore; wherein each of the plurality of diverters has, when seated on oneof the plurality of perforations, a first surface facing the perforationopening and a second surface facing generally in the direction of acenter line of the well bore, the area of the first surface beinggreater than the area of the perforation opening, and wherein each ofthe diverters, when seated, presents a cross-sectional area to hydraulicfracture fluid flowing through the well bore during pumping that issubstantially smaller than the first and the second surface areas. 13.The method of claim 12, wherein each of the plurality of diverters has ashape substantially similar to the shape of an object chosen from agroup consisting essentially of a discus, erythrocyte, saucer, disk, andwafer.
 14. The method of claim 12, wherein each of the plurality ofdiverters is hollow.
 15. The method of claim 12, wherein each of theplurality of diverters is capable of withstanding a differentialpressure of at least 5,000 pounds per square inch.
 16. The method ofclaim 12, wherein each of the plurality of diverters, when seated on oneof the plurality of perforations, presents a cross-sectional area to theflow of hydraulic fracture fluid through the well bore during pumpingthat is 25% or less than the cross-sectional area presented by aball-shaped diverter seated on the one of the plurality of perforations.17. The method of claim 12 wherein the permeability of the subterraneanformation adjacent to those of the plurality of perforations beingobstructed and temporarily sealed by the diverters is greater than thepermeability of the remaining ones of the plurality of perforations notbeing obstructed and temporarily sealed by the diverters.
 18. A diverterfor obstructing and temporarily sealing at least a portion of aperforation of a predetermined size or smaller in casing of a well borein a subterranean formation during hydraulic fracturing, the divertercomprising an impermeable body having a cross-sectional maximumthickness that is substantially smaller than its maximum width ormaximum length, the thickness being measured along a first axis, thelength along a second axis and the width along a third axis, the first,second and third axes being mutually orthogonal; wherein the maximumwidth and length are sufficient for the diverter to obstruct andtemporarily seal the perforation; and wherein the maximum thickness issufficiently small to avoid the diverter, when seated on a perforation,from being removed from the perforation by hydraulic fracture fluidflowing past the diverter to other perforations in the casing not sealedwith a diverter when the hydraulic fracture fluid is flowing into thewell bore at or below a predetermined maximum rate.
 19. The diverter ofclaim 18, wherein the impermeable body is shaped as a discus, a saucer,a disk, a wafer, or an erythrocyte.
 20. The diverter of claim 18,wherein the diverter is capable of withstanding a differential pressureof at least 5,000 pounds per square inch.
 21. A non-spherical diverterfor obstructing and temporarily sealing a perforation in a well casingin a subterranean formation during hydraulic fracturing, the divertercomprising an impermeable body that, when seated on a perforation, has afirst surface generally facing the perforation opening and a secondsurface facing generally in the opposite direction, toward a center lineof the well, the area of the second surface being greater than the areaof the perforation opening; wherein the body, when seated on aperforation, presents a cross-sectional area to a flow of hydraulicfracture fluid through the well that is substantially smaller than thefirst and the second surface areas.
 22. The diverter of claim 21 whereinthe cross-sectional area presented to a flow of hydraulic fracture bythe diverter when it is seated on a perforation does not exceed 25% ofthat presented by a spherically shaped diverter having a diameter of notless than the maximum width and the maximum length when seated on theperforation.
 23. The diverter of claim 21, wherein the diverter has ashape substantially similar to the shape of an object chosen from agroup consisting essentially of a discus, erythrocyte, saucer, disk, andwafer.
 24. The diverter of claim 21, wherein the body of the diverter isrelatively rigid and does not fail when subject to a differentialpressure of at least 5,000 psi.
 25. The diverter of claim 21, whereinthe body has coating on its surface that is flexible to enhance sealingof the perforations.
 26. The diverter of claim 21, wherein the secondsurface of the body is flat.
 27. The diverter of claim 18, wherein thesecond surface of the body is curved.